Notes to Condensed Consolidated Financial Statements (Unaudited)
SilverBow Resources, Inc. and Subsidiary
(1) General Information
SilverBow Resources, Inc. (“SilverBow,” the “Company,” or “we”) is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas. Being a committed and long-term operator in South Texas, the Company possesses a significant understanding of the reservoirs in the region. We leverage this competitive understanding to assemble high quality drilling inventory while continuously enhancing our operations to maximize returns on capital invested.
The condensed consolidated financial statements included herein are unaudited and certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2020.
(2) Summary of Significant Accounting Policies
Basis of Presentation. The condensed consolidated financial statements included herein reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation.
Principles of Consolidation. The accompanying condensed consolidated financial statements include the accounts of SilverBow and its wholly owned subsidiary, SilverBow Resources Operating LLC, which are engaged in the exploration, development, acquisition, and operation of oil and gas properties, with a focus on oil and natural gas reserves in the Eagle Ford trend in Texas. Our undivided interests in oil and gas properties are accounted for using the proportionate consolidation method, whereby our proportionate share of the assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying condensed consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying condensed consolidated financial statements.
COVID-19. The spread of COVID-19 and its impact on the global supply of and demand for crude oil caused volatility in the market price for crude oil during 2020. The spot price of West Texas Intermediate (“WTI”) crude oil declined over 50% in March and April of 2020 before gradually improving through the rest of 2020 and into the first half of 2021. The spot price of Brent and WTI crude oil closed at approximately $64 and $59 per barrel, respectively, on March 31, 2021, and approximately $77 and $74 per barrel, respectively, on June 30, 2021.
In response to these market conditions, including the COVID-19 pandemic and the volatility in oil prices during 2020, the Company released its sole drilling rig in April 2020 and deferred the completion and placement on production of eight wells until the second half of 2020. In the third quarter of 2020, the Company restarted completions activity and returned to sales all previously curtailed volumes as of December 31, 2020.
As a result of the COVID-19 pandemic, the Company operated under a “work from home” policy applicable to all employees other than essential personnel whose physical presence was required either in the office or in the field until March 2021. Effective March 2021, the Company adjusted its “work from home” policy to a flexible work schedule, so that all employees returned to the corporate office, on a weekly rotation, while continuing to work from home. Except as described above regarding the curtailment of production in 2020, SilverBow has not experienced any material interruption to its ordinary course business processes as a result of the COVID-19 pandemic and the volatility in oil and gas prices. The Company will continue to monitor the COVID-19 situation and follow the advice of government and health leaders.
Subsequent Events. We have evaluated subsequent events requiring potential accrual or disclosure in our condensed consolidated financial statements.
On August 3, 2021, we acquired additional working interest in 12 wells that we currently operate and additional acreage in Webb County for total aggregate consideration of approximately $24 million.
Through July 30, 2021, the Company entered into additional derivative contracts. The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts entered into after June 30, 2021:
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Oil Derivative Contracts
(New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”) Settlements)
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Total Volumes
(Bbls)(1)
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Weighted-Average Price
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2021 Contracts
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3Q21
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30,000
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$
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70.75
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3Q21 (2)
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12,000
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$
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72.76
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4Q21
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81,250
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$
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66.69
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2022 Contracts
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1Q22
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45,000
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$
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63.37
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2Q22
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45,500
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$
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62.00
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3Q22
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46,000
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$
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60.81
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4Q22
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46,000
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$
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59.75
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(1) Bbl refers to one barrel of oil.
(2) Transaction for a swap purchase to reduce overall hedge position.
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Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
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Total Volumes
(MMBtu)
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Weighted-Average Price
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Weighted-Average Collar Floor Price
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Weighted-Average Collar Call Price
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Swap Contracts
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2021 Contracts
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3Q21
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610,000
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$
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4.00
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4Q21
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1,240,000
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$
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3.90
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2022 Contracts
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2Q22
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3,795,000
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$
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2.99
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3Q22
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4,140,000
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$
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3.02
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4Q22
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2,760,000
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$
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3.14
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Collar Contracts
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2022 Contracts
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4Q22
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1,380,000
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$
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2.90
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$
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3.34
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2023 Contracts
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1Q23
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1,350,000
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$
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2.95
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$
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3.51
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2Q23
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2,275,000
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$
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2.40
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$
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2.84
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NGL Swaps (Mont Belvieu)
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Total Volumes
(Bbls)
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Weighted-Average Price
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2022 Contracts
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1Q22
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45,000
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$
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26.32
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2Q22
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45,500
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$
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26.32
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3Q22
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46,000
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$
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26.32
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4Q22
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46,000
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$
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26.32
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There were no other material subsequent events requiring additional disclosure in these condensed consolidated financial statements.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. Such estimates and assumptions are subject to a number of risks and uncertainties that
may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:
•the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, the related present value of estimated future net cash flows therefrom, and the Ceiling Test impairment calculation,
•estimates related to the collectability of accounts receivable and the creditworthiness of our customers,
•estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,
•estimates of future costs to develop and produce reserves,
•accruals related to oil and gas sales, capital expenditures and lease operating expenses (“LOE”),
•estimates in the calculation of share-based compensation expense,
•estimates of our ownership in properties prior to final division of interest determination,
•the estimated future cost and timing of asset retirement obligations,
•estimates made in our income tax calculations, including the valuation of our deferred tax assets,
•estimates in the calculation of the fair value of commodity derivative assets and liabilities,
•estimates in the assessment of current litigation claims against the Company,
•estimates in amounts due with respect to open state regulatory audits, and
•estimates on future lease obligations.
While we are not currently aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, reallocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which relate to prior periods. These types of adjustments cannot be currently estimated and are expected to be recorded in the period during which the adjustments are known.
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.
Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended June 30, 2021 and 2020, such internal costs when capitalized totaled $1.2 million and $0.9 million, respectively. For the six months ended June 30, 2021 and 2020, such internal costs capitalized totaled $2.3 million and $2.0 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 6 of these Notes to Condensed Consolidated Financial Statements for further discussion on capitalized interest costs).
The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances (in thousands):
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June 30, 2021
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December 31, 2020
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Property and Equipment
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Proved oil and gas properties
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$
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1,372,163
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$
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1,310,008
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Unproved oil and gas properties
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24,312
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28,090
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Furniture, fixtures and other equipment
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5,727
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5,275
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Less – Accumulated depreciation, depletion, amortization & impairment
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(830,749)
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(801,279)
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Property and Equipment, Net
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$
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571,453
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$
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542,094
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No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.
We compute the provision for depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties, including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties, by an overall rate determined by dividing the physical units of oil and natural gas produced (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions. The period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.
Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved oil and gas properties” and therefore subject to amortization. G&G costs incurred that are associated with unproved properties are capitalized in “Unproved oil and gas properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, economic conditions, capital availability and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.
Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10% and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).
The quarterly calculations of the Ceiling Test and provision for DD&A are based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.
Due to the effects of pricing and timing of projects we reported a non-cash impairment write-down, on a pre-tax basis, of $260.3 million and $355.9 million for the three and six months ended June 30, 2020, respectively, on our oil and natural gas properties. There was no impairment for the three and six months ended June 30, 2021.
If future capital expenditures outpace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, it is possible that non-cash write-downs of our oil and natural gas properties will occur again in the future. We cannot control and cannot predict what future prices for oil and natural gas will be; therefore, we cannot estimate the amount of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices. However, it is reasonably possible that we will record additional Ceiling Test write-downs in future periods.
Accounts Receivable, Net. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2021 and December 31, 2020, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable, net” balance on the accompanying condensed consolidated balance sheets.
At June 30, 2021, our “Accounts receivable, net” balance included $23.9 million for oil and gas sales, $0.6 million due from joint interest owners, $1.0 million for severance tax credit receivables and $0.4 million for other receivables. At December 31, 2020, our “Accounts receivable, net” balance included $18.8 million for oil and gas sales, $4.0 million due from joint interest owners, $2.4 million for severance tax credit receivables and $0.7 million for other receivables.
Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate, including our wells, in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net,” on the accompanying condensed consolidated statements of operations. The amount of supervision fees charged for each of the six months ended June 30, 2021 and 2020 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated was $1.2 million and $0.9 million for the three months ended June 30, 2021 and 2020, respectively, and $2.4 million and $2.2 million for the six months ended June 30, 2021 and 2020, respectively.
Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws. In March and April 2020, the COVID-19 pandemic caused volatility in the market price for crude oil due to the disruption of global supply and demand. In response to these market conditions and given the decline in oil prices and economic outlook for our Company, during the quarter ended June 30, 2020 management determined that it was not more likely than not that the Company would realize future cash benefits from its remaining federal carryover items and other federal deferred tax assets and, accordingly, recorded a full valuation allowance in the second quarter to offset its net federal deferred tax assets in excess of deferred tax liabilities. As a result of the full valuation allowance established at June 30, 2020, we recorded an income tax provision of $22.4 million and $21.2 million for the three and six months ended June 30, 2020, respectively, which was inclusive of state income tax expense. The Company maintains a full valuation allowance against its net federal deferred tax assets in excess of deferred tax liabilities as of June 30, 2021.
Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At June 30, 2021, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.
On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”). The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer-side Social Security payments, net operating loss carryback periods, alternative minimum tax credit refunds and modifications to the net interest deduction limitation. The Company continues to examine the impact that the CARES Act may have on its business but does not currently expect the CARES Act to have a material effect on its financial condition, results of operation, or liquidity.
Revenue Recognition. Our reported oil and gas sales are comprised of revenues from oil, natural gas and natural gas liquids (“NGLs”) sales. Revenues from each product stream are recognized at the point when control of the product is transferred to the customer and collectability is reasonably assured. Prices for our products are either negotiated on a monthly basis or tied to market indices. The Company has determined that these contracts represent performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point. Natural gas revenues are recognized based on the actual volume of natural gas sold to the purchasers.
The following table provides information regarding our oil and gas sales, by product, reported on the Condensed Consolidated Statements of Operations for the three months ended June 30, 2021 and 2020 and the six months ended June 30, 2021 and 2020 (in thousands):
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Three Months Ended June 30, 2021
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Three Months Ended June 30, 2020
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Six Months Ended June 30, 2021
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Six Months Ended June 30, 2020
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Oil, natural gas and NGLs sales:
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Oil
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$
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15,890
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$
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5,265
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$
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33,356
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|
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$
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23,315
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Natural gas
|
46,791
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18,103
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109,705
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49,574
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NGLs
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7,180
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1,478
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13,541
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|
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5,333
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Total
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$
|
69,861
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$
|
24,846
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$
|
156,602
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|
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$
|
78,222
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Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):
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June 30, 2021
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December 31, 2020
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Trade accounts payable
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$
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8,736
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$
|
15,930
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Accrued operating expenses
|
2,873
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|
|
2,491
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Accrued compensation costs
|
2,579
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|
|
3,771
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Asset retirement obligations – current portion
|
515
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|
441
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Accrued non-income based taxes
|
2,517
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|
1,819
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Accrued corporate and legal fees
|
143
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|
150
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Other payables
|
6,524
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|
|
2,389
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Total accounts payable and accrued liabilities
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$
|
23,887
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|
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$
|
26,991
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Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.
Treasury Stock. Our treasury stock repurchases are reported at cost and are included in “Treasury stock, held at cost” on the accompanying condensed consolidated balance sheets. For the six months ended June 30, 2021 and 2020, we purchased 74,146 and 27,773 treasury shares, respectively, to satisfy withholding tax obligations arising upon the vesting of restricted shares.
(3) Leases
The Company adopted the standard provided in the Financial Accounting Standards Board's Accounting Standards Update 2016-02 and elected the package of practical expedients that allows an entity to carry forward historical accounting treatment relating to lease identification and classification for existing leases upon adoption and the practical expedient related to land easements that allows an entity to carry forward historical accounting treatment for land easements on existing agreements. The Company has made an accounting policy election to keep leases with an initial term of 12 months or less off the Consolidated Balance Sheets. We have elected to not account for lease and non-lease components separately.
The Company has contractual agreements for its corporate office lease, vehicle fleet, compressors, treating equipment, and for surface use rights. For leases with a primary term of more than 12 months, a right-of-use (“ROU”) asset and the corresponding lease liability is recorded. The Company determines at inception if an arrangement is an operating or financing lease. As of June 30, 2021, all of the Company’s leases were operating leases.
The initial asset and liability balances are recorded at the present value of the payment obligations over the lease term. If lease terms include options to extend the lease and it is reasonably certain that the Company will exercise that option, the lease term used for capitalization includes the expected renewal periods. Most leases do not provide an implicit interest rate. Unless the lease contract contains an implicit interest rate, the Company uses its incremental borrowing rate at the time of lease inception to compute the fair value of the lease payments. The ROU asset balance and current and non-current lease liabilities are reported separately on the accompanying Condensed Consolidated Balance Sheets. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease payments are not included in ROU assets and lease liabilities. Leases with an initial term of 12 months or less are not recorded on the balance sheet. The Company recognizes lease expense on a straight-line basis over the lease term.
Lease costs represent the straight-line lease expense of ROU assets and short-term leases. The components of lease cost are classified as follows (in thousands):
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Three Months Ended June 30, 2021
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Three Months Ended June 30, 2020
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Six Months Ended June 30, 2021
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Six Months Ended June 30, 2020
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Lease Costs Included in the Asset Additions in the Condensed Consolidated Balance Sheets
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Property, plant and equipment acquisitions - short-term leases
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$
|
1,491
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$
|
118
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|
|
$
|
1,820
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|
|
$
|
2,302
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Property, plant and equipment acquisitions - operating leases
|
—
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|
5
|
|
|
—
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|
|
10
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Total lease costs in property, plant and equipment additions
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$
|
1,491
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|
|
$
|
123
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|
|
$
|
1,820
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|
|
$
|
2,312
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Three Months Ended June 30, 2021
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Three Months Ended June 30, 2020
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Six Months Ended June 30, 2021
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Six Months Ended June 30, 2020
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|
Lease Costs Included in the Condensed Consolidated Statements of Operations
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|
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|
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Lease operating expenses - short-term leases
|
$
|
618
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|
|
$
|
650
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|
|
$
|
1,085
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|
|
$
|
900
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|
|
Lease operating expenses - operating leases
|
1,106
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|
|
1,433
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|
|
2,270
|
|
|
2,870
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General and administrative, net - operating leases
|
178
|
|
|
179
|
|
|
351
|
|
|
359
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|
|
Total lease cost expensed
|
$
|
1,902
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|
|
$
|
2,262
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|
|
$
|
3,706
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|
|
$
|
4,129
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|
The lease term and the discount rate related to the Company's leases are as follows:
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
Weighted-average remaining lease term (in years)
|
3.1
|
|
Weighted-average discount rate
|
4.1
|
%
|
As of June 30, 2021, the Company's future undiscounted cash payment obligation for its operating lease liabilities are as follows (in thousands):
|
|
|
|
|
|
|
|
|
As of June 30, 2021
|
|
2021 (Remaining)
|
$
|
3,462
|
|
|
2022
|
6,443
|
|
|
2023
|
5,642
|
|
|
2024
|
742
|
|
|
2025
|
742
|
|
|
Thereafter
|
856
|
|
|
Total undiscounted lease payments
|
17,887
|
|
|
Present value adjustment
|
(1,188)
|
|
|
Net operating lease liabilities
|
$
|
16,699
|
|
Supplemental cash flow information related to leases was as follows (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2021
|
|
Six Months Ended June 30, 2020
|
|
Cash paid for amounts included in the measurement of lease liabilities;
|
|
|
|
|
Operating cash flows from operating leases
|
$
|
2,618
|
|
|
$
|
3,225
|
|
|
Investing cash flows from operating leases
|
$
|
—
|
|
|
$
|
10
|
|
(4) Share-Based Compensation
Share-Based Compensation Plans
In 2016, the Company adopted the 2016 Equity Incentive Plan (as amended from time to time, the “2016 Plan”). The Company also adopted the Inducement Plan (as amended from time to time, the “Inducement Plan,” and, together with the 2016 Plan, the “Plans”) on December 15, 2016. Under the Plans, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur.
The Company computes a deferred tax benefit for restricted stock units (“RSUs”), performance-based stock units (“PSUs”) and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For RSUs, the Company's actual tax deduction is based on the value of the units at the time of vesting.
The expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations was $1.2 million for both the three months ended June 30, 2021 and 2020 and $2.3 million and $2.4 million for the six months ended June 30, 2021 and 2020,
respectively. Capitalized share-based compensation was less than $0.1 million for both the three months ended June 30, 2021 and 2020 and $0.1 million for both the six months ended June 30, 2021 and 2020.
We view stock option awards and RSUs with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.
Stock Option Awards
The compensation cost related to stock option awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to five years). We use the Black-Scholes option pricing model to estimate the fair value of stock option awards.
At June 30, 2021, we had $0.4 million of unrecognized compensation cost related to stock option awards. The following table provides information regarding stock option award activity for the six months ended June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares
|
|
Wtd. Avg. Exer. Price
|
|
Options outstanding, beginning of period
|
303,705
|
|
|
$
|
27.73
|
|
|
|
|
|
|
|
Options forfeited
|
(3,896)
|
|
|
$
|
16.96
|
|
|
Options expired
|
(23,800)
|
|
|
$
|
23.25
|
|
|
|
|
|
|
|
Options outstanding, end of period
|
276,009
|
|
|
$
|
28.12
|
|
|
Options exercisable, end of period
|
226,950
|
|
|
$
|
28.53
|
|
Our outstanding stock option awards had $0.1 million measurable aggregate intrinsic value at June 30, 2021. At June 30, 2021, the weighted-average remaining contract life of stock option awards outstanding was 4.6 years and exercisable was 4.4 years. The total intrinsic value of stock option awards exercisable was less than $0.1 million for the six months ended June 30, 2021.
Restricted Stock Units
The compensation cost related to restricted stock awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to five years).
As of June 30, 2021, we had $1.9 million unrecognized compensation expense related to our RSUs which is expected to be recognized over a weighted-average period of 1.0 years.
The following table provides information regarding RSU activity for the six months ended June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RSUs
|
|
Wtd. Avg. Grant Price
|
|
RSUs outstanding, beginning of period
|
574,916
|
|
|
$
|
9.02
|
|
|
RSUs granted
|
100,178
|
|
|
$
|
8.33
|
|
|
|
|
|
|
|
|
|
|
|
|
RSUs forfeited
|
(17,802)
|
|
|
$
|
11.09
|
|
|
RSUs vested
|
(310,645)
|
|
|
$
|
9.02
|
|
|
RSUs outstanding, end of period
|
346,647
|
|
|
$
|
8.71
|
|
Performance-Based Stock Units
On February 20, 2018, the Company granted 30,700 PSUs for which the number of shares earned is based on the total shareholder return (“TSR”) of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2018 to December 31, 2020. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the date of valuation was $41.66 per unit or 150.61% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards had a cliff-vesting period of three years and there are no outstanding awards as of June 30, 2021.
On May 21, 2019, the Company granted 99,500 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2019 to December 31, 2021. The awards contain market conditions which allow a payout ranging between 0% payout and 200% of the target payout. The fair value as of the grant date was $18.86 per unit or 112.9% of stock price. The awards have a cliff-vesting period of three years. There were 83,600 PSUs outstanding related to this award as of June 30, 2021.
On February 24, 2021, the Company granted 161,389 PSUs for which the number of shares earned is based on the TSR of the Company's common stock relative to the TSR of its selected peers during the performance period from January 1, 2021 to December 31, 2022. The awards contain market conditions which allow a payout ranging between 0% and 200% of the target payout. The fair value as of the grant date was $13.13 per unit or 157.6% of the stock price. The compensation expense for these awards is based on the per unit grant date valuation using a Monte Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff-vesting period of two years. All PSUs granted remain outstanding related to this award as of June 30, 2021.
As of June 30, 2021, we had $2.2 million unrecognized compensation expense related to our PSUs based on the assumption of 100% target payout. The remaining weighted-average performance period is 1.3 years while 23,800 shares vested during the six months ended June 30, 2021.
(5) Earnings Per Share
Basic earnings per share (“Basic EPS”) has been computed using the weighted-average number of common shares outstanding during each period. Diluted earnings per share (“Diluted EPS”) assumes, as of the beginning of the period, exercise of stock options and RSU grants using the treasury stock method. Diluted EPS also assumes conversion of PSUs to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and RSU grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and six months ended June 30, 2021 and 2020 are discussed below.
The following is a reconciliation of the numerators and denominators used in the calculation of Basic EPS and Diluted EPS for the periods indicated below (in thousands, except per share amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2021
|
|
Three Months Ended June 30, 2020
|
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Share Amounts
|
$
|
(19,951)
|
|
|
12,190
|
|
|
$
|
(1.64)
|
|
|
$
|
(305,976)
|
|
|
11,910
|
|
|
$
|
(25.69)
|
|
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RSU Awards
|
|
|
—
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Assumed Share Conversions
|
$
|
(19,951)
|
|
|
12,190
|
|
|
$
|
(1.64)
|
|
|
$
|
(305,976)
|
|
|
11,910
|
|
|
$
|
(25.69)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2021
|
|
Six Months Ended June 30, 2020
|
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Net Income (Loss)
|
|
Shares
|
|
Per Share
Amount
|
|
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Share Amounts
|
$
|
8,429
|
|
|
12,110
|
|
|
$
|
0.70
|
|
|
$
|
(311,834)
|
|
|
11,868
|
|
|
$
|
(26.28)
|
|
|
Dilutive Securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
RSU Awards
|
|
|
269
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (Loss) and Assumed Share Conversions
|
$
|
8,429
|
|
|
12,379
|
|
|
$
|
0.68
|
|
|
$
|
(311,834)
|
|
|
11,868
|
|
|
$
|
(26.28)
|
|
Approximately 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for both the three months ended June 30, 2021 and 2020 because they were antidilutive due to the net loss, while 0.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the six months ended June 30, 2021 because they were antidilutive, while 0.3 million stock options to purchase shares were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss.
Less than approximately 0.1 million and 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the three months ended June 30, 2021 and 2020, respectively, because they were antidilutive due to the net loss, while 0.1 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the six months ended June 30, 2021 because they were antidilutive while 0.2 million of RSUs that could be converted to common shares were not included in the computation of Diluted EPS for the six months ended June 30, 2020 because they were antidilutive due to the net loss.
There were no antidilutive shares of PSUs that could be converted to common shares for the three months ended June 30, 2021, while approximately 0.1 million shares of PSUs were not included for the three months ended June 30, 2020 because they were antidilutive due to the net loss, while 0.1 million shares of PSUs were not included for the six months ended June 30, 2021 because they were antidilutive, while 0.1 million shares of PSUs were not included for the six months ended June 30, 2020 because they were antidilutive due to the net loss.
(6) Long-Term Debt
The Company's long-term debt consisted of the following (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2021
|
|
December 31, 2020
|
|
Credit Facility Borrowings (1)
|
$
|
198,000
|
|
|
$
|
230,000
|
|
|
Second Lien Notes due 2024
|
200,000
|
|
|
200,000
|
|
|
|
398,000
|
|
|
430,000
|
|
|
Unamortized discount on Second Lien Notes due 2024
|
(1,157)
|
|
|
(1,295)
|
|
|
Unamortized debt issuance cost on Second Lien Notes due 2024
|
(3,397)
|
|
|
(3,800)
|
|
|
Long-Term Debt, net
|
$
|
393,446
|
|
|
$
|
424,905
|
|
(1) Unamortized debt issuance costs on our Credit Facility borrowings are included in “Other Long-Term Assets” in our consolidated balance sheet. As of June 30, 2021 and December 31, 2020, we had $3.0 million and $1.4 million, respectively, in unamortized debt issuance costs on our Credit Facility borrowings.
Revolving Credit Facility. Amounts outstanding under our Credit Facility (defined below) were $198.0 million and $230.0 million as of June 30, 2021 and December 31, 2020, respectively. The Company is a party to a First Amended and Restated Senior Secured Revolving Credit Agreement with JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto, as amended (such agreement, the “Credit Agreement” and the borrowing facility provided thereby, the “Credit Facility”). In conjunction with its regularly scheduled semi-annual redetermination, the Company entered into the Seventh Amendment to the Credit Facility, effective April 16, 2021 (the “Seventh Amendment”), which among other things, (i) redetermined the borrowing base under the Credit Facility to $300 million (from $310 million), (ii) extended the maturity of our Credit Facility from April 19, 2022 to April 19, 2024; (iii) increased the applicable margin used to calculate the interest rate under the Credit Facility by 50 basis points, with the specific applicable margins determined by reference to borrowing base utilization; (iv) reduced the permitted ratio of Total Debt to EBITDA (each as defined in the Credit Agreement) from 3.50 to 1.00 (a) to 3.25 to 1.00 for the fiscal quarters ending on or before December 31, 2021 and (b) to 3.00 to 1.00 commencing with the fiscal quarter ending March 31, 2022; (v) implemented a minimum rolling hedge requirement of 50% of reasonably anticipated projected production from proved developed producing reserves for a 24-month period, and (vi) increased the mortgage coverage and title requirements from 85% to 90%.
The Credit Facility provides for a maximum credit amount of $600.0 million, subject to the current borrowing base of $300.0 million as of June 30, 2021. The borrowing base is regularly redetermined on or about May and November of each calendar year and is subject to additional adjustments from time to time, including for asset sales, elimination or reduction of hedge positions and incurrence of other debt. Additionally, the Company and the administrative agent may request an unscheduled redetermination of the borrowing base between scheduled redeterminations. The amount of the borrowing base is determined by the lenders, in their discretion, in accordance with their oil and gas lending criteria at the time of the relevant redetermination. The Company may also request the issuance of letters of credit under the Credit Agreement in an aggregate amount up to $25 million, which reduces the amount of available borrowings under the borrowing base in the amount of such issued and outstanding letters of credit. Maintaining or increasing our borrowing base under our Credit Facility is dependent on
many factors, including commodity prices, our hedge positions, changes in our lenders' lending criteria and our ability to raise capital to drill wells to replace produced reserves.
Interest under the Credit Facility accrues at the Company’s option either at an Alternate Base Rate plus the applicable margin (“ABR Loans”) or the LIBOR Rate plus the applicable margin (“Eurodollar Loans”). Effective April 16, 2021, the applicable margin ranged from 2.25% to 3.25% for ABR Loans and 3.25% to 4.25% for Eurodollar Loans. The Alternate Base Rate and LIBOR Rate are defined, and the applicable margins are set forth, in the Credit Agreement. Undrawn amounts under the Credit Facility are subject to a 0.5% commitment fee. To the extent that a payment default exists and is continuing, all amounts outstanding under the Credit Facility will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. In July 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. At the present time, the Credit Facility is subject to LIBOR rates but has a term that extends beyond the end of 2021 when LIBOR will be phased out. The Credit Agreement provides for options in the event LIBOR is discontinued.
The obligations under the Credit Agreement are secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and its subsidiary, including a first priority lien on properties attributed with at least 90% of estimated proved reserves of the Company and its subsidiary.
The Credit Agreement contains the following financial covenants:
•a ratio of total debt to earnings before interest, tax, depreciation and amortization (“EBITDA”), as defined in the Credit Agreement, for the most recently completed four fiscal quarters, not to exceed (i) 3.25 to 1.00 as of the last day of each fiscal quarter for any fiscal quarter ending on or before December 31, 2021 and (ii) 3.00 to 1.00 as of the last day of each fiscal quarter, commencing with fiscal quarter ending March 31, 2022; and
•a current ratio, as defined in the Credit Agreement, which includes in the numerator available borrowings undrawn under the borrowing base, of not less than 1.00 to 1.00 as of the last day of each fiscal quarter.
As of June 30, 2021, the Company was in compliance with all financial covenants under the Credit Agreement.
Additionally, the Credit Agreement contains certain representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Credit Agreement contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Credit Facility to be immediately due and payable.
Total interest expense on the Credit Facility, which includes commitment fees and amortization of debt issuance costs, was $2.8 million and $3.5 million for the three months ended June 30, 2021 and 2020, respectively, and $5.3 million and $6.9 million for the six months ended June 30, 2021 and 2020, respectively.
There was no capitalized interest on our unproved properties for both the three months ended June 30, 2021 and 2020, respectively, and for both the six months ended June 30, 2021 and 2020, respectively.
Senior Secured Second Lien Notes. On December 15, 2017, the Company entered into a Note Purchase Agreement for Senior Secured Second Lien Notes (as amended, the “Note Purchase Agreement,” and such second lien facility the “Second Lien”) among the Company as issuer, U.S. Bank National Association as agent and collateral agent, and certain holders that are a party thereto, and issued notes in an initial principal amount of $200.0 million, with a $2.0 million discount, for net proceeds of $198.0 million. The Company has the ability, subject to the satisfaction of certain conditions (including compliance with the Asset Coverage Ratio described below and the agreement of the holders to purchase such additional notes), to issue additional notes in a principal amount not to exceed $100.0 million. The Second Lien matures on December 15, 2024.
Interest on the Second Lien is payable quarterly and accrues at LIBOR plus 7.5%; provided that if LIBOR ceases to be available, the Second Lien provides for a mechanism to use ABR (an alternate base rate) plus 6.5% as the applicable interest rate. The definitions of LIBOR and ABR are set forth in the Note Purchase Agreement. To the extent that a payment, insolvency, or, at the holders’ election, another default exists and is continuing, all amounts outstanding under the Second Lien will bear interest at 2.0% per annum above the rate and margin otherwise applicable thereto. Additionally, to the extent the Company were to default on the Second Lien, this would potentially trigger a cross-default under our Credit Facility.
The Company has the right, to the extent permitted under the Credit Facility and subject to the terms and conditions of the Second Lien, to optionally prepay the notes, subject to a repayment fee of 1.0% of the principal amount of the Second Lien being prepaid through December 15, 2021; and thereafter, no premium. Additionally, the Second Lien contains customary mandatory prepayment obligations upon asset sales (including hedge terminations), casualty events and incurrences of certain debt, subject to, in certain circumstances, reinvestment periods. Management believes the probability of mandatory prepayment due to default is remote.
The obligations under the Second Lien are secured, subject to certain exceptions and other permitted liens (including the liens created under the Credit Facility), by a perfected security interest, second in priority to the liens securing our Credit Facility, and mortgage lien on substantially all assets of the Company and its subsidiary, including a mortgage lien on oil and gas properties attributed with at least 85% of estimated PV-9 (defined below), of proved reserves of the Company and its subsidiary and 85% of the book value attributed to the PV-9 of the non-proved oil and gas properties of the Company. PV-9 is determined using commodity price assumptions by the administrative agent of the Credit Facility. PV-9 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 9%.
The Second Lien contains an Asset Coverage Ratio, which is only tested (i) as a condition to issuance of additional notes and (ii) in connection with certain asset sales in order to determine whether the proceeds of such asset sale must be applied as a prepayment of the notes and includes in the numerator of the PV-10 (defined below), based on forward strip pricing, plus the swap mark-to-market value of the commodity derivative contracts of the Company and its restricted subsidiary and in the denominator the total net indebtedness of the Company and its restricted subsidiary, of not less than 1.25 to 1.0 as of each date of determination (the “Asset Coverage Ratio”). PV-10 value is the estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%.
The Second Lien also contains a financial covenant measuring the ratio of total net debt-to-EBITDA, as defined in the Note Purchase Agreement, for the most recently completed four fiscal quarters, not to exceed 4.5 to 1.0 as of the last day of each fiscal quarter. As of June 30, 2021, the Company was in compliance with all financial covenants under the Second Lien.
The Second Lien contains certain customary representations, warranties and covenants, including but not limited to, limitations on incurring debt and liens, limitations on making certain restricted payments, limitations on investments, limitations on asset sales and hedge unwinds, limitations on transactions with affiliates and limitations on modifying organizational documents and material contracts. The Second Lien contains customary events of default. If an event of default occurs and is continuing, the lenders may declare all amounts outstanding under the Second Lien to be immediately due and payable.
As of June 30, 2021, total net amounts recorded for the Second Lien were $195.4 million, net of unamortized debt discount and debt issuance costs. Interest expense on the Second Lien totaled $4.6 million for both the three months ended June 30, 2021 and 2020, respectively, and $9.2 million and $9.5 million for the six months ended June 30, 2021 and 2020, respectively.
Debt Issuance Costs. Our policy is to capitalize upfront commitment fees and other direct expenses associated with our line of credit arrangement and then amortize such costs ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings. During the three months ended June 30, 2021 in connection with our semi-annual redetermination, the Company capitalized $2.4 million for expenses incurred under the Seventh Amendment to our Credit Facility. Additionally the Company wrote-off $0.2 million in debt issuance costs related to lenders which fully exited the Credit Facility.
(7) Acquisitions and Dispositions
Effective December 22, 2017, the Company closed a purchase and sale contract to sell the Company's wellbores and facilities in the Bay De Chene field and recorded a $16.3 million obligation related to the funding of certain plugging and abandonment costs. Of the $16.3 million original obligation, $1.1 million and $0.4 million was paid during the six months ended June 30, 2021 and 2020, respectively. The remaining obligation under this contract is $0.5 million and is carried in the accompanying condensed consolidated balance sheet current liability in “Accounts payable and accrued liabilities” as of June 30, 2021.
(8) Price-Risk Management Activities
Derivatives are recorded on the balance sheet at fair value with changes in fair value recognized in earnings. The changes in the fair value of our derivatives are recognized in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations. The Company's price-risk management policy is to use derivative instruments to protect against declines in oil and natural gas prices, primarily through the purchase of commodity price swaps and collars as well as basis swaps.
During the three months ended June 30, 2021 and 2020, the Company recorded losses of $46.1 million and losses of $8.5 million, respectively, on its commodity derivatives. During the six months ended June 30, 2021 and 2020, the Company recorded losses of $64.3 million and gains of $79.8 million, respectively. The Company made cash payments of $10.7 million and collected cash payments of $67.5 million for settled derivative contracts during the six months ended June 30, 2021 and 2020, respectively. Included in our collected cash payments during the six months ended June 30, 2020 was $38.3 million for monetized derivative contracts.
At June 30, 2021 and December 31, 2020, there were $0.4 million and $0.8 million, respectively, in receivables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts receivable, net” and were subsequently collected in July 2021 and January 2021, respectively. At June 30, 2021 and December 31, 2020, we also had $5.1 million and $0.8 million, respectively, in payables for settled derivatives which were included on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and were subsequently paid in July 2021 and January 2021, respectively.
The fair values of our swap contracts are computed using observable market data whereas our collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. At June 30, 2021, there was $0.7 million and less than $0.1 million in current unsettled derivative assets and long-term unsettled derivative assets, respectively, and $45.4 million and $10.3 million in current and long-term unsettled derivative liabilities, respectively. At December 31, 2020, there was $4.8 million and $0.3 million in current and long-term unsettled derivative assets, respectively, and $8.2 million and $2.9 million in current and long-term unsettled derivative liabilities, respectively.
The Company uses an International Swap and Derivatives Association master agreement for our derivative contracts. This is an industry-standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying condensed consolidated balance sheet. Under the right of set-off, there was a $54.9 million net fair value liability at June 30, 2021, and a $6.0 million net fair value liability at December 31, 2020. For further discussion related to the fair value of the Company's derivatives, refer to Note 9 of these Notes to Condensed Consolidated Financial Statements.
The following tables summarize the weighted-average prices as well as future production volumes for our future derivative contracts in place as of June 30, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Derivative Contracts
(New York Mercantile Exchange (“NYMEX”) WTI Settlements)
|
|
Total Volumes
(Bbls)
|
|
Weighted-Average Price
|
|
Weighted-Average Collar Floor Price
|
|
Weighted-Average Collar Call Price
|
|
Swap Contracts
|
|
|
|
|
|
|
|
|
|
2021 Contracts
|
|
|
|
|
|
|
|
|
|
3Q21
|
|
179,759
|
|
|
$
|
51.19
|
|
|
|
|
|
|
4Q21
|
|
191,412
|
|
|
$
|
53.60
|
|
|
|
|
|
|
2022 Contracts
|
|
|
|
|
|
|
|
|
|
1Q22
|
|
178,455
|
|
|
$
|
45.77
|
|
|
|
|
|
|
2Q22
|
|
91,000
|
|
|
$
|
54.00
|
|
|
|
|
|
|
3Q22
|
|
200,100
|
|
|
$
|
47.05
|
|
|
|
|
|
|
4Q22
|
|
138,000
|
|
|
$
|
53.20
|
|
|
|
|
|
|
2023 Contracts
|
|
|
|
|
|
|
|
|
|
1Q23
|
|
81,900
|
|
|
$
|
55.70
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
2021 Contracts
|
|
|
|
|
|
|
|
|
|
3Q21
|
|
90,620
|
|
|
|
|
$
|
34.34
|
|
|
$
|
39.87
|
|
|
4Q21
|
|
84,640
|
|
|
|
|
$
|
34.70
|
|
|
$
|
41.01
|
|
|
2022 Contracts
|
|
|
|
|
|
|
|
|
|
1Q22
|
|
40,500
|
|
|
|
|
$
|
40.00
|
|
|
$
|
45.55
|
|
|
2Q22
|
|
115,850
|
|
|
|
|
$
|
39.25
|
|
|
$
|
46.20
|
|
|
2023 Contracts
|
|
|
|
|
|
|
|
|
|
2Q23
|
|
36,400
|
|
|
|
|
$
|
56.00
|
|
|
$
|
63.20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Derivative Contracts
(NYMEX Henry Hub Settlements)
|
|
Total Volumes
(MMBtu)
|
|
Weighted-Average Price
|
|
Weighted-Average Collar Floor Price
|
|
Weighted-Average Collar Call Price
|
|
Swap Contracts
|
|
|
|
|
|
|
|
|
|
2021 Contracts
|
|
|
|
|
|
|
|
|
|
3Q21
|
|
330,000
|
|
|
$
|
2.62
|
|
|
|
|
|
|
4Q21
|
|
290,000
|
|
|
$
|
2.69
|
|
|
|
|
|
|
2022 Contracts
|
|
|
|
|
|
|
|
|
|
3Q22
|
|
2,100
|
|
|
$
|
2.50
|
|
|
|
|
|
|
Collar Contracts
|
|
|
|
|
|
|
|
|
|
2021 Contracts
|
|
|
|
|
|
|
|
|
|
3Q21
|
|
8,185,175
|
|
|
|
|
$
|
2.36
|
|
|
$
|
2.82
|
|
|
4Q21
|
|
8,991,000
|
|
|
|
|
$
|
2.61
|
|
|
$
|
2.98
|
|
|
2022 Contracts
|
|
|
|
|
|
|
|
|
|
1Q22
|
|
8,465,000
|
|
|
|
|
$
|
2.72
|
|
|
$
|
3.36
|
|
|
2Q22
|
|
5,246,500
|
|
|
|
|
$
|
2.15
|
|
|
$
|
2.60
|
|
|
3Q22
|
|
4,899,000
|
|
|
|
|
$
|
2.39
|
|
|
$
|
2.72
|
|
|
4Q22
|
|
4,545,076
|
|
|
|
|
$
|
2.41
|
|
|
$
|
2.88
|
|
|
2023 Contracts
|
|
|
|
|
|
|
|
|
|
1Q23
|
|
4,297,000
|
|
|
|
|
$
|
2.62
|
|
|
$
|
3.11
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Derivative Swaps
(East Texas Houston Ship Channel vs. NYMEX Settlements)
|
|
Total Volumes
(MMBtu)
|
|
Weighted-Average Price
|
|
2021 Contracts
|
|
|
|
|
|
3Q21
|
|
10,120,000
|
|
|
$
|
(0.022)
|
|
|
4Q21
|
|
11,040,000
|
|
|
$
|
(0.013)
|
|
|
2022 Contracts
|
|
|
|
|
|
1Q22
|
|
6,300,000
|
|
|
$
|
0.052
|
|
|
2Q22
|
|
2,730,000
|
|
|
$
|
(0.063)
|
|
|
3Q22
|
|
2,760,000
|
|
|
$
|
(0.063)
|
|
|
4Q22
|
|
2,760,000
|
|
|
$
|
(0.063)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Basis Swaps
(Argus Cushing (WTI) and Magellan East Houston)
|
|
Total Volumes (Bbls)
|
|
Weighted-Average Price
|
|
2021 Contracts
|
|
|
|
|
|
3Q21
|
|
262,200
|
|
|
$
|
1.27
|
|
|
4Q21
|
|
241,500
|
|
|
$
|
1.28
|
|
|
Calendar Monthly Roll Differential Swaps
|
|
|
|
|
|
2021 Contracts
|
|
|
|
|
|
3Q21
|
|
253,000
|
|
|
$
|
(0.34)
|
|
|
4Q21
|
|
241,500
|
|
|
$
|
(0.33)
|
|
|
2022 Contracts
|
|
|
|
|
|
1Q22
|
|
216,000
|
|
|
$
|
0.09
|
|
|
2Q22
|
|
218,400
|
|
|
$
|
0.09
|
|
|
3Q22
|
|
220,800
|
|
|
$
|
0.09
|
|
|
4Q22
|
|
220,800
|
|
|
$
|
0.09
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NGL Swaps (Mont Belvieu)
|
|
Total Volumes
(Bbls)
|
|
Weighted-Average Price
|
|
2021 Contracts
|
|
|
|
|
|
3Q21
|
|
192,324
|
|
|
$
|
24.26
|
|
|
4Q21
|
|
192,324
|
|
|
$
|
24.26
|
|
|
2022 Contracts
|
|
|
|
|
|
1Q22
|
|
45,000
|
|
|
$
|
23.52
|
|
(9) Fair Value Measurements
Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives, the Credit Facility and the Second Lien. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.
The fair values of our derivative contracts are computed using observable market data whereas our derivative collar contracts are valued using a Black-Scholes pricing model and are periodically verified against quotes from brokers. These are considered Level 2 valuations (defined below).
The carrying value of our Credit Facility and Second Lien approximates fair value because the respective borrowing rates do not materially differ from market rates for similar borrowings. These are considered Level 3 valuations (defined below).
The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value:
Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.
Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that are obtained from independent third-party sources.
Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets.
The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of each of June 30, 2021 and December 31, 2020, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 8 of these Notes to Condensed Consolidated Financial Statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements at
|
|
(in millions)
|
Total
|
|
Quoted Prices in
Active markets for
Identical Assets
(Level 1)
|
|
Significant Other
Observable Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
|
June 30, 2021
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Basis Derivatives
|
$
|
0.3
|
|
|
$
|
—
|
|
|
$
|
0.3
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Oil Basis Derivatives
|
0.4
|
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
22.8
|
|
|
—
|
|
|
22.8
|
|
|
—
|
|
|
Natural Gas Basis Derivatives
|
1.6
|
|
|
—
|
|
|
1.6
|
|
|
—
|
|
|
Oil Derivatives
|
25.7
|
|
|
—
|
|
|
25.7
|
|
|
—
|
|
|
Oil Basis Derivatives
|
1.0
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
NGL Derivatives
|
4.5
|
|
|
—
|
|
|
4.5
|
|
|
—
|
|
|
December 31, 2020
|
|
|
|
|
|
|
|
|
Assets
|
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
1.5
|
|
|
—
|
|
|
1.5
|
|
|
—
|
|
|
Natural Gas Basis Derivatives
|
1.1
|
|
|
—
|
|
|
1.1
|
|
|
—
|
|
|
Oil Derivatives
|
2.5
|
|
|
—
|
|
|
2.5
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
|
|
|
|
Natural Gas Derivatives
|
4.0
|
|
|
—
|
|
|
4.0
|
|
|
—
|
|
|
Natural Gas Basis Derivatives
|
0.4
|
|
|
—
|
|
|
0.4
|
|
|
—
|
|
|
Oil Derivatives
|
5.9
|
|
|
—
|
|
|
5.9
|
|
|
—
|
|
|
Oil Basis Derivatives
|
0.8
|
|
|
—
|
|
|
0.8
|
|
|
—
|
|
Our current and long-term unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Fair value of commodity derivatives” and “Fair Value of Long-Term Commodity Derivatives,” respectively.
(10) Asset Retirement Obligations
Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management's expectation of future cost environments and other unobservable inputs. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3 fair value measurements. When a liability is initially recorded, the carrying amount of the related asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs upon initial recording, excluding salvage values.
The following provides a roll-forward of our asset retirement obligations for the year ended December 31, 2020 and the six months ended June 30, 2021 (in thousands):
|
|
|
|
|
|
|
|
Asset Retirement Obligations as of December 31, 2019
|
$
|
4,447
|
|
|
Accretion expense
|
354
|
|
|
Liabilities incurred for new wells and facilities construction
|
281
|
|
|
|
|
|
Reductions due to plugged wells and facilities
|
(103)
|
|
|
Revisions in estimates
|
(5)
|
|
|
Asset Retirement Obligations as of December 31, 2020
|
$
|
4,974
|
|
|
Accretion expense
|
148
|
|
|
Liabilities incurred for new wells and facilities construction
|
292
|
|
|
|
|
|
Reductions due to plugged wells and facilities
|
(157)
|
|
|
Revisions in estimates
|
(156)
|
|
|
Asset Retirement Obligations as of June 30, 2021
|
$
|
5,101
|
|
At June 30, 2021 and December 31, 2020, approximately $0.5 million and $0.4 million, respectively, of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.
(11) Commitments and Contingencies
In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as an operator of oil and natural gas wells. In our management's opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis in conjunction with the Company's financial information and its condensed consolidated financial statements and accompanying notes included in this report and its audited consolidated financial statements and accompanying notes included in its Annual Report on Form 10-K for the year ended December 31, 2020. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 35 of this report.
Company Overview
SilverBow is an independent oil and gas company headquartered in Houston, Texas. The Company's strategy is focused on acquiring and developing assets in the Eagle Ford Shale located in South Texas where it has assembled approximately 130,000 net acres across five operating areas. SilverBow's acreage position in each of its operating areas is highly contiguous and designed for optimal and efficient horizontal well development. The Company has built a balanced portfolio of properties with a significant base of current production and reserves coupled with low-risk development drilling opportunities and meaningful upside from newer operating areas.
Being a committed and long-term operator in South Texas, SilverBow possesses a significant understanding of the reservoir characteristics, geology, landowners and competitive landscape in the region. The Company leverages this in-depth knowledge to continue to assemble high quality drilling inventory while continuously enhancing its operations to maximize returns on capital invested.
Operational Results
Total production for the six months ended June 30, 2021 increased 6% from the six months ended June 30, 2020 to 197 million cubic feet of natural gas equivalent per day as SilverBow pursued a moderated growth strategy and did not have any curtailed production impacting results.
During the second quarter of 2021, SilverBow drilled 10 wells, completed one well and brought one well online. Drilling and completion (“D&C”) spending during the quarter was primarily related to drilling activity in the liquids-rich La Salle Condensate area. As previously planned, the Company accelerated activity of its mid-year oil development program. Due to further reduced drilling cycle times and efficiencies, SilverBow was able to drill three additional wells in the second quarter. Notably, the Company drilled a four well pad in approximately 25 days, or six days per well on average. First production from the nine La Salle Condensate wells is expected in the third quarter of 2021. SilverBow is reviewing early data and appraising its Austin Chalk acreage through the one well completed in the second quarter.
SilverBow continues to further its capital and operational efficiencies across its operating areas. Year-to-date, the Company drilled 20% more lateral feet per day and reduced drilling costs by 9% compared to 2020. On the completion side, SilverBow completed 17% more stages per day, pumped 8% more proppant per day and reduced completion costs by 2%. Taken altogether, D&C costs per lateral foot are 5% lower in 2021 as compared to 2020.
Production management remains a key focus area for the Company, and the maintenance and optimization projects executed during the first quarter of 2021 continue to support strong performance from the developed production base. In the second quarter of 2021, further base production optimizations were realized through expanded compression and artificial lift installations. This focus on base production management is driving production uplifts with shallower declines. The continued outperformance of SilverBow's initial Austin Chalk well, which came online in February 2021, further supported its production base during the second quarter. As of the date of this report, the well is still producing above 10 million cubic feet of natural gas per day (“MMcf/d”) and has produced a cumulative 1.9 billion cubic feet (“Bcf”) over the first five months.
For the third quarter of 2021, SilverBow plans to drill six net wells across the McMullen Oil and Webb County Gas areas, and complete and bring online 11 net wells across the La Salle Condensate, McMullen Oil and Webb County Gas areas. The development program reflects the acceleration of liquids-rich wells planned earlier this year, as well as a balancing of high-rate gas wells to capture favorable prices heading into year-end. Not included in the well counts are three gross (one net) non-operated wells in the Webb Count Gas area, which the Company has elected to participate in during the third quarter of 2021, and which adds approximately $5 million to the full year capital budget. By early fourth quarter 2021, SilverBow expects substantially all its D&C activity for the year to be incurred.
The Company has revised its capital budget for full year 2021 to a range of $115-$130 million. The revised range will enable SilverBow to capitalize on a favorable commodity price backdrop while generating greater cash flow.
Through the first half of 2021, the Company maintained zero recordable incidents. Safety is core to SilverBow’s operations and the Company has demonstrated a commitment to delivering high-returns through its industry-leading safety environment.
2021 Cost Reduction Initiatives: SilverBow continues to focus on cost reduction measures in the areas that it can control. These initiatives include the use of regional sand in completions and improved utilization of existing facilities. As previously mentioned, the Company continues to improve its process for drilling, completing and equipping wells. SilverBow's procurement team takes a process-oriented approach to reducing the total delivered costs of purchased services by examining costs at their most granular level. Services are routinely sourced directly from the suppliers. The Company's LOE and workover expenses were $11.9 million or $0.33 per thousand cubic feet of gas equivalent (“Mcfe”) for the first six months of 2021, as compared to $10.8 million or $0.32 per Mcfe for the same period in 2020. The increase in costs was due to incremental expenses related to Winter Storm Uri, higher utilities and higher compression costs. These increases were partially mitigated by lower chemical, treating and salt water disposal costs.
SilverBow's net general and administrative (“net G&A”) costs were $9.6 million, or $0.27 per Mcfe, and cash G&A costs were $7.4 million (a non-GAAP financial measure calculated as net G&A costs less $2.3 million of share-based compensation), or $0.21 per Mcfe, for the first six months of 2021, compared to net G&A costs of $12.1 million, or $0.36 per Mcfe, and cash G&A costs of $9.7 million (a non-GAAP financial measure calculated as net G&A costs less $2.4 million of share-based compensation), or $0.29 per Mcfe, for the six months ended June 30, 2020.
SilverBow reports cash G&A because it believes this measure is commonly used by management, analysts and investors as an indicator of cost management and operating efficiency on a comparable basis from period to period. In addition, the Company believes cash G&A expenses are used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis of G&A spend without regard to stock-based compensation programs which can vary substantially from company to company. Cash G&A expenses should not be considered as an alternative to, or more meaningful than, total net G&A expenses.
Liquidity and Capital Resources
SilverBow's primary use of cash has been to fund capital expenditures to develop its oil and gas properties and to repay Credit Facility borrowings. As of June 30, 2021, the Company’s liquidity consisted of $2.1 million of cash-on-hand and $102.0 million in available borrowings on its Credit Facility, which had a $300 million borrowing base. Management believes the Company has sufficient liquidity to meet its obligations through the third quarter of 2022 and execute its long-term development plans. For more details, see the Credit Facility section within Note 6 to SilverBow's condensed consolidated financial statements for more information on its Credit Facility.
Contractual Commitments and Obligations
As of June 30, 2021 and December 31, 2020, the Company had approximately $16.7 million and $4.4 million, respectively, in net operating leases liabilities. The increase was primarily due to compression equipment leases and the Company's corporate office lease. There were no other material changes in SilverBow's contractual commitments during the six months ended June 30, 2021 from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2020.
Off-Balance Sheet Arrangements
As of June 30, 2021, the Company had no off-balance sheet arrangements requiring disclosure pursuant to Item 303(a) of Regulation S-K.
Summary of 2021 Financial Results Through June 30, 2021
•Revenues and Net Income (Loss): The Company's oil and gas revenues were $156.6 million for the six months ended June 30, 2021, compared to $78.2 million for the six months ended June 30, 2020. Revenues were higher due to increased production volumes and overall higher commodity pricing. The Company's net income was $8.4 million for the six months ended June 30, 2021, compared to a net loss of $311.8 million for the six months ended June 30, 2020. The increase in net income was primarily due to higher revenues due to increased production volumes and higher commodity pricing along with no non-cash impairment write-down during the current year.
•Capital Expenditures: The Company's capital expenditures on an accrual basis were $58.7 million for the six months ended June 30, 2021 compared to $55.5 million for the six months ended June 30, 2020. The expenditures for the six months ended June 30, 2021 and 2020 were primarily attributable to drilling and completion activity.
•Working Capital: The Company had a working capital deficit of $70.1 million at June 30, 2021 and a working capital deficit of $23.1 million at December 31, 2020. The working capital computation does not include available liquidity through our Credit Facility.
•Cash Flows: For the six months ended June 30, 2021, the Company generated cash from operating activities of $93.2 million, of which $1.9 million was attributable to changes in working capital. Cash used for property additions was $57.0 million. This excluded $1.3 million attributable to a net increase of capital-related payables and accrued costs. Additionally, $1.1 million was paid during the six months ended June 30, 2021 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net repayments on the Credit Facility were $32.0 million during the six months ended June 30, 2021.
For the six months ended June 30, 2020, the Company generated cash from operating activities of $99.0 million, of which $4.1 million was attributable to changes in working capital. Cash used for property additions was $85.6 million. This included $28.6 million attributable to a net decrease of capital-related payables and accrued costs. Additionally, $0.4 million was paid during the six months ended June 30, 2020 for property abandonment obligations related to the sale of our former Bay De Chene field. The Company’s net repayments on the Credit Facility were $9.0 million during the six months ended June 30, 2020.
Results of Operations
Revenues — Three Months Ended June 30, 2021 and Three Months Ended June 30, 2020
Natural gas production was 82% of the Company's production volumes for both the three months ended June 30, 2021 and 2020. Natural gas sales were 67% and 73% of oil and gas sales for the three months ended June 30, 2021 and 2020, respectively.
Crude oil production was 8% and 10% of the Company's production volumes for both the three months ended June 30, 2021 and 2020, respectively. Crude oil sales were 23% and 21% of oil and gas sales for the three months ended June 30, 2021 and 2020, respectively.
NGL production was 10% and 8% of the Company's production volumes for the three months ended June 30, 2021 and 2020, respectively. NGL sales were 10% and 6% of oil and gas sales for both the three months ended June 30, 2021 and 2020, respectively.
The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the three months ended June 30, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fields
|
|
Three Months Ended June 30, 2021
|
|
Three Months Ended June 30, 2020
|
|
|
|
Oil and Gas Sales
(In Millions)
|
Net Oil and Gas Production
Volumes (MMcfe)
|
|
Oil and Gas Sales
(In Millions)
|
Net Oil and Gas Production
Volumes (MMcfe)
|
|
Artesia Wells
|
|
$
|
15.7
|
|
3,491
|
|
|
$
|
4.4
|
|
1,872
|
|
|
AWP
|
|
14.1
|
|
2,249
|
|
|
5.3
|
|
2,189
|
|
|
Fasken
|
|
28.8
|
|
9,754
|
|
|
12.8
|
|
7,511
|
|
|
Other (1)
|
|
11.2
|
|
3,873
|
|
|
2.3
|
|
1,312
|
|
|
Total
|
|
$
|
69.8
|
|
19,367
|
|
|
$
|
24.8
|
|
12,884
|
|
(1) Primarily composed of the Company's Rio Bravo, Oro Grande and Uno Mas fields.
The sales volumes increase from 2020 to 2021 was primarily due to overall increased production as a result of increased drilling and completion activity during 2021 and return of volumes that had been curtailed during 2020.
In the second quarter of 2021, our $45.0 million, or 181%, increase in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $33.7 million favorable impact on sales due to overall higher commodity pricing; and
•Volume variances that had an approximately $11.3 million favorable impact on sales due to overall increased commodity production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the three months ended June 30, 2021 and 2020 (in thousands, except per-dollar amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2021
|
Three Months Ended June 30, 2020
|
|
Production volumes:
|
|
|
|
|
Oil (MBbl) (1)
|
|
250
|
|
221
|
|
|
Natural gas (MMcf)
|
|
15,879
|
|
10,624
|
|
|
Natural gas liquids (MBbl) (1)
|
|
332
|
|
156
|
|
|
Total (MMcfe)
|
|
19,367
|
|
12,884
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales:
|
|
|
|
|
Oil
|
|
$
|
15,890
|
|
$
|
5,265
|
|
|
Natural gas
|
|
46,791
|
|
18,103
|
|
|
Natural gas liquids
|
|
7,180
|
|
1,478
|
|
|
Total
|
|
$
|
69,861
|
|
$
|
24,846
|
|
|
|
|
|
|
|
Average realized price:
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
63.62
|
|
$
|
23.82
|
|
|
Natural gas (per Mcf)
|
|
2.95
|
|
1.70
|
|
|
Natural gas liquids (per Bbl)
|
|
21.65
|
|
9.49
|
|
|
Average per Mcfe
|
|
$
|
3.61
|
|
$
|
1.93
|
|
|
|
|
|
|
|
Price impact of cash-settled derivatives:
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
(20.49)
|
|
$
|
49.52
|
|
|
Natural gas (per Mcf)
|
|
(0.13)
|
|
0.64
|
|
|
Natural gas liquids (per Bbl)
|
|
(2.79)
|
|
—
|
|
|
Average per Mcfe
|
|
$
|
(0.42)
|
|
$
|
1.38
|
|
|
|
|
|
|
|
Average realized price including impact of cash-settled derivatives:
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
43.13
|
|
$
|
73.34
|
|
|
Natural gas (per Mcf)
|
|
2.82
|
|
2.34
|
|
|
Natural gas liquids (per Bbl)
|
|
18.86
|
|
9.49
|
|
|
Average per Mcfe
|
|
$
|
3.19
|
|
$
|
3.31
|
|
|
|
|
|
|
|
|
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.
For the three months ended June 30, 2021 and 2020, the Company recorded net losses of $46.1 million and $8.5 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
Costs and Expenses — Three Months Ended June 30, 2021 and Three Months Ended June 30, 2020
The following table provides additional information regarding our expenses for the three months ended June 30, 2021 and 2020 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
Three Months Ended June 30, 2021
|
Three Months Ended June 30, 2020
|
|
General and administrative, net
|
$
|
4,834
|
|
$
|
6,180
|
|
|
Depreciation, depletion, and amortization
|
16,039
|
|
13,716
|
|
|
Accretion of asset retirement obligations
|
74
|
|
88
|
|
|
Lease operating expenses
|
5,515
|
|
5,000
|
|
|
Workovers
|
76
|
|
—
|
|
|
Transportation and gas processing
|
6,206
|
|
4,554
|
|
|
Severance and other taxes
|
3,577
|
|
2,037
|
|
|
Interest expense, net
|
7,436
|
|
8,026
|
|
|
Write-down of oil and gas properties
|
—
|
|
260,342
|
|
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.25 and $0.48 for the three months ended June 30, 2021 and 2020, respectively. The decrease per Mcfe was due to higher production while the decrease in costs was primarily due to lower salaries and burdens, professional fees and lower temporary labor fees. Included in general and administrative expenses is $1.2 million in share-based compensation for both of the three months ended June 30, 2021 and 2020, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $0.83 and $1.06 for the three months ended June 30, 2021 and 2020, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs in the previous year.
Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.29 and $0.39 for the three months ended June 30, 2021 and 2020, respectively. The decrease per Mcfe was mainly due to increased production. The increase in costs was due to higher compression and salt water disposal costs, partially offset by lower treating and labor costs.
Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.32 and $0.35 for the three months ended June 30, 2021 and 2020, respectively.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.18 and $0.16 for the three months ended June 30, 2021 and 2020, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.1% and 8.2% for the three months ended June 30, 2021 and 2020, respectively.
Interest. Our gross interest cost was $7.4 million and $8.0 million for the three months ended June 30, 2021 and 2020, respectively. The decrease in gross interest cost is primarily due to decreased borrowings. There were no capitalized interest costs for the three months ended June 30, 2021 or 2020.
Write-down of oil and gas properties. Due to the effects of pricing and timing of projects, for the three months ended June 30, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $260.3 million on our oil and natural gas properties. There was no impairment for the three months ended June 30, 2021.
Revenues — Six Months Ended June 30, 2021 and Six Months Ended June 30, 2020
Natural gas production was 80% and 81% of the Company's production volumes for the six months ended June 30, 2021 and 2020, respectively. Natural gas sales were 70% and 63% of oil and gas sales for the six months ended June 30, 2021 and 2020, respectively.
Crude oil production was 10% and 11% of the Company's production volumes for both the six months ended June 30, 2021 and 2020, respectively. Crude oil sales were 21% and 30% of oil and gas sales for the six months ended June 30, 2021 and 2020, respectively.
NGL production was 10% and 8% of the Company's production volumes for the six months ended June 30, 2021 and 2020, respectively. NGL sales were 9% and 7% of oil and gas sales for both the six months ended June 30, 2021 and 2020, respectively.
The following table provides additional information regarding the Company's oil and gas sales, by area, excluding any effects of the Company's hedging activities, for the six months ended June 30, 2021 and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fields
|
|
Six Months Ended June 30, 2021
|
|
Six Months Ended June 30, 2020
|
|
|
|
Oil and Gas Sales
(In Millions)
|
Net Oil and Gas Production
Volumes (MMcfe)
|
|
Oil and Gas Sales
(In Millions)
|
Net Oil and Gas Production
Volumes (MMcfe)
|
|
Artesia Wells
|
|
$
|
30.2
|
|
6,743
|
|
|
$
|
18.8
|
|
6,215
|
|
|
AWP
|
|
31.1
|
|
4,964
|
|
|
18.6
|
|
5,214
|
|
|
Fasken
|
|
61.8
|
|
16,554
|
|
|
31.2
|
|
17,176
|
|
|
Other (1)
|
|
33.5
|
|
7,330
|
|
|
9.6
|
|
5,054
|
|
|
Total
|
|
$
|
156.6
|
|
35,591
|
|
|
$
|
78.2
|
|
33,659
|
|
(1) Primarily composed of the Company's Rio Bravo, Oro Grande and Uno Mas fields.
The sales volumes increase from 2020 to 2021 was primarily due to increased natural gas production partially offset by lower oil production in 2021 as well as the return of volumes that had been curtailed in 2020.
In the six months ended June 30, 2021, our $78.4 million, or 100%, increase in oil, NGL and natural gas sales from the prior year period resulted from:
•Price variances that had an approximately $76.3 million favorable impact on sales due to overall higher commodity pricing; and
•Volume variances that had an approximately $2.1 million favorable impact on sales due to higher natural gas and NGL production.
The following table provides additional information regarding our oil and gas sales, by commodity type, as well as the effects of our hedging activities for derivative contracts held to settlement, for the six months ended June 30, 2021 and 2020 (in thousands, except per-dollar amounts):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2021
|
Six Months Ended June 30, 2020
|
|
Production volumes:
|
|
|
|
|
Oil (MBbl) (1)
|
|
565
|
|
622
|
|
|
Natural gas (MMcf)
|
|
28,502
|
|
27,121
|
|
|
Natural gas liquids (MBbl) (1)
|
|
617
|
|
468
|
|
|
Total (MMcfe)
|
|
35,591
|
|
33,659
|
|
|
|
|
|
|
|
Oil, natural gas and natural gas liquids sales:
|
|
|
|
|
Oil
|
|
$
|
33,356
|
|
$
|
23,315
|
|
|
Natural gas
|
|
109,705
|
|
49,574
|
|
|
Natural gas liquids
|
|
13,541
|
|
5,333
|
|
|
Total
|
|
$
|
156,602
|
|
$
|
78,222
|
|
|
|
|
|
|
|
Average realized price:
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
59.09
|
|
$
|
37.51
|
|
|
Natural gas (per Mcf)
|
|
3.85
|
|
1.83
|
|
|
Natural gas liquids (per Bbl)
|
|
21.95
|
|
11.40
|
|
|
Average per Mcfe
|
|
$
|
4.40
|
|
$
|
2.32
|
|
|
|
|
|
|
|
Price impact of cash-settled derivatives:
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
(16.17)
|
|
$
|
24.75
|
|
|
Natural gas (per Mcf)
|
|
(0.08)
|
|
0.55
|
|
|
Natural gas liquids (per Bbl)
|
|
(2.45)
|
|
—
|
|
|
Average per Mcfe
|
|
$
|
(0.36)
|
|
$
|
0.90
|
|
|
|
|
|
|
|
Average realized price including impact of cash-settled derivatives:
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
42.91
|
|
$
|
62.26
|
|
|
Natural gas (per Mcf)
|
|
3.77
|
|
2.38
|
|
|
Natural gas liquids (per Bbl)
|
|
19.50
|
|
11.40
|
|
|
Average per Mcfe
|
|
$
|
4.04
|
|
$
|
3.23
|
|
|
|
|
|
|
|
|
(1) Oil and natural gas liquids are converted at the rate of one barrel to six Mcfe. Mcf refers to one thousand cubic feet, and MMcf refers to one million cubic feet. Bbl refers to one barrel of oil, and MBbl refers to one thousand barrels.
For the six months ended June 30, 2021 and 2020, the Company recorded net losses of $64.3 million and net gains of $79.8 million from our derivatives activities, respectively. Hedging activity is recorded in “Gain (loss) on commodity derivatives, net” on the accompanying condensed consolidated statements of operations.
Costs and Expenses — Six Months Ended June 30, 2021 and Six Months Ended June 30, 2020
The following table provides additional information regarding our expenses for the three months ended June 30, 2021 and 2020 (in thousands):
|
|
|
|
|
|
|
|
|
|
|
Costs and Expenses
|
Six Months Ended June 30, 2021
|
Six Months Ended June 30, 2020
|
|
General and administrative, net
|
$
|
9,616
|
|
$
|
12,093
|
|
|
Depreciation, depletion, and amortization
|
29,431
|
|
37,156
|
|
|
Accretion of asset retirement obligations
|
148
|
|
173
|
|
|
Lease operating expenses
|
11,789
|
|
10,812
|
|
|
Workovers
|
90
|
|
—
|
|
|
Transportation and gas processing
|
11,262
|
|
11,197
|
|
|
Severance and other taxes
|
7,066
|
|
5,001
|
|
|
Interest expense, net
|
14,454
|
|
16,433
|
|
|
Write-down of oil and gas properties
|
—
|
|
355,948
|
|
General and Administrative Expenses, Net. These expenses on a per-Mcfe basis were $0.27 and $0.36 for the six months ended June 30, 2021 and 2020, respectively. The decrease per Mcfe was due to higher production while the decrease in costs was primarily due to lower salaries and burdens, professional fees and temporary labor fees. Included in general and administrative expenses is $2.3 million and $2.4 million in share-based compensation for the six months ended June 30, 2021 and 2020, respectively.
Depreciation, Depletion and Amortization. These expenses on a per-Mcfe basis were $0.83 and $1.10 for the six months ended June 30, 2021 and 2020, respectively. The decrease on a per Mcfe basis was driven by reductions to our depletable base due to non-cash impairment write-downs in the previous year.
Lease Operating Expenses and Workovers. These expenses on a per-Mcfe basis were $0.33 and $0.32 for the six months ended June 30, 2021 and 2020, respectively. The increase in costs was due to higher compression and salt water disposal costs, partially offset by lower treating and labor costs.
Transportation and Gas Processing. These expenses are related to natural gas and NGL sales. These expenses on a per-Mcfe basis were $0.32 and $0.33 for the six months ended June 30, 2021 and 2020, respectively.
Severance and Other Taxes. These expenses on a per-Mcfe basis were $0.20 and $0.15 for the six months ended June 30, 2021 and 2020, respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 4.5% and 6.4% for the three months ended June 30, 2021 and 2020, respectively.
Interest. Our gross interest cost was $14.5 million and $16.4 million for the six months ended June 30, 2021 and 2020, respectively. The decrease in gross interest cost is primarily due to decreased borrowings. There were no capitalized interest costs for the six months ended June 30, 2021 or 2020.
Write-down of oil and gas properties. Due to the effects of pricing and timing of projects, for the six months ended June 30, 2020, we reported a non-cash impairment write-down, on a pre-tax basis, of $355.9 million on our oil and natural gas properties. There was no impairment for the six months ended June 30, 2021.
Critical Accounting Policies and New Accounting Pronouncements
There have been no changes in the critical accounting policies disclosed in our 2020 Annual Report on Form 10-K.
Forward-Looking Statements
This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are based on current expectations and assumptions and are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, including those regarding our strategy, future operations, financial position, well expectations and drilling plans, estimated production levels, expected oil and natural gas pricing, estimated oil and natural gas reserves or the present value thereof, reserve increases, capital expenditures, budget, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “budgeted,” “guidance,” “expect,” “may,” “continue,” “predict,” “potential,” “plan,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, the following risks and uncertainties:
• the severity and duration of world health events, including the COVID-19 pandemic, related economic repercussions, including disruptions in the oil and gas industry;
• actions by the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and allied producing countries with respect to oil production levels and announcements of potential changes in such levels;
• operational challenges relating to the COVID-19 pandemic and efforts to mitigate the spread of the virus, including logistical challenges, protecting the health and well-being of our employees, remote work arrangements, performance of contracts and supply chain disruptions;
• shut-in and curtailment of production due to decreases in available storage capacity or other factors;
• volatility in natural gas, oil and NGL prices;
• future cash flows and their adequacy to maintain our ongoing operations;
• liquidity, including our ability to satisfy our short- or long-term liquidity needs;
• our borrowing capacity and future covenant compliance;
• operating results;
• asset disposition efforts or the timing or outcome thereof;
• ongoing and prospective joint ventures, their structures and substance, and the likelihood of their finalization or the timing thereof;
• the amount, nature and timing of capital expenditures, including future development costs;
• timing, cost and amount of future production of oil and natural gas;
• availability of drilling and production equipment or availability of oil field labor;
• availability, cost and terms of capital;
• timing and successful drilling and completion of wells;
• availability and cost for transportation of oil and natural gas;
• costs of exploiting and developing our properties and conducting other operations;
• competition in the oil and natural gas industry;
• general economic conditions;
• opportunities to monetize assets;
• our ability to execute on strategic initiatives;
• effectiveness of our risk management activities including hedging strategy;
• environmental liabilities;
• counterparty credit risk;
• governmental regulation and taxation of the oil and natural gas industry;
• developments in world oil and natural gas markets and in oil and natural gas-producing countries;
• uncertainty regarding our future operating results; and
• other risks and uncertainties described in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2020.
All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk Factors" in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2020 and in subsequent Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.
All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events, except as required by law.